The present invention relates to a method of monitoring a force applied to a component in a wellbore following drilling of a wellbore, and to an assembly for use in performing an operation in a well following drilling of a wellbore. In particular, but not exclusively, the present invention relates to a method for monitoring the weight and/or torque applied to a component in a well. The present invention also relates more generally to a method of monitoring a parameter in a wellbore during performance of an operation in a well, which involves operating a fluid pressure pulse generating device to transmit data relating to the change in the at least one parameter to surface.
In the oil and gas exploration and production industry, wellbore fluids comprising oil and/or gas are recovered to surface through a wellbore which is drilled from surface. The wellbore is conventionally drilled using a string of tubing known as a drill string, which includes a drilling assembly that terminates in a drill bit. Drilling fluid known as drilling ‘mud’ is passed down the string of tubing to the bit, to perform functions including cooling the bit and carrying drill cuttings back to surface along the annulus defined between the wellbore wall and the drill string.
Following drilling, the well construction procedure generally requires that the wellbore be lined with metal wellbore-lining tubing, which is known in the industry as ‘casing’. The casing serves numerous purposes, including: supporting the drilled rock formations; preventing undesired ingress/egress of fluid; and providing a pathway through which further tubing and downhole tools can pass. The casing comprises sections of tubing which are coupled together end-to-end. Typically, the wellbore is drilled to a first depth and a casing of a first diameter installed in the drilled wellbore. The casing extends along the length of the drilled wellbore to surface, where it terminates in a wellhead assembly. The casing is sealed in place by pumping ‘cement’ down the casing, which flows out of the bottom of the casing and along the annulus.
Following appropriate testing, the wellbore is normally extended to a second depth, by drilling a smaller diameter extension of the wellbore through a cement plug at the bottom of the first, larger diameter wellbore section. A smaller diameter second casing is then installed in the extended portion of the wellbore, extending up through the first casing to the wellhead. The second casing is then also cemented in place. This process is repeated as necessary, until the wellbore has been extended to a desired depth, from which access to a rock formation containing hydrocarbons (oil and/or gas) can be achieved. Frequently, a wellbore-lining tubing is located in the wellbore which does not extend to the wellhead, but is tied into and suspended (or ‘hung’) from the preceding casing section. This tubing is typically referred to in the industry as a ‘liner’. The liner is similarly cemented in place within the drilled wellbore. When the casing/liner has been installed and cemented, the well is ‘completed’ so that well fluids can be recovered, typically by installing a string of production tubing extending to surface.
The well construction procedure which is chosen will depend on factors including physical parameters of the drilled rock formation, the required physical properties of the wellbore (e.g. depth, bore diameter), and other physical characteristics such as the prevailing temperature and hydrostatic pressure. Available options include open hole completions, where the casing is set above the rock formation or zone of interest and well fluids flow into the open casing; liner completions, where a liner is installed across the zone of interest and fluid flows into the liner (through control equipment such as sliding sleeve valves); and perforated casing/liner completions. Whichever construction procedure that is chosen, care must be taken not to apply excessive weight and/or torque to the equipment employed in the construction/completion procedure, particularly the casing/liner.
For example, where a liner is employed, a sealing device known as a packer is provided at the top of the liner, at the interface with the casing. A packer of this type is usually referred to in the industry as a ‘liner-top packer’. The packer seals the annular region defined between an external wall of the liner, an internal wall of the larger diameter casing that the liner is located in, and the upper surface of cement that has been supplied into the wellbore to seal the liner. The packer may be carried by the liner or deployed independently, and includes a sealing element which can be deformed radially outwardly into sealing abutment with the wall of the casing. Deformation of the sealing element is typically achieved mechanically, for example by axially compressing the sealing element, by allowing a certain amount of ‘weight’ to be set down on the packer.
Obtaining verification that the packer has been correctly mechanically set, and so provides an adequate seal, is difficult. In the past, the only way of assessing whether a packer had been correctly set was to monitor the weight applied to the packer at surface, that is the axial load imparted upon the packer to urge the sealing element radially outwardly. However, the weight observed at surface often does not correspond to that experienced by the packer, which may be positioned many hundreds of meters downhole. This is a particular problem in deviated wellbores, where it is difficult to apply the necessary weight to set the packer. It has been found that there can be a considerable reduction of the weight and torque felt by the packer compared to that applied at surface, due to frictional contact with the walls of the wellbore or tubing in the well. Typically, the only indication that a packer had not been set correctly was if an unexpected leak/pressure drop was detected at surface, such as when pressure testing the liner to check for pressure integrity.
Similar difficulties have also been encountered in other steps in wellbore construction activities, where data relating to the activity in question is difficult to obtain.
It has been known to monitor the ‘weight on bit’ and torque applied during the drilling phase, using sensors (strain gauges) for monitoring these parameters in a drilling environment. However, a particular problem associated with measuring weight on bit is pressure and temperature effects on the measurements taken. In particular, during the drilling phase, mud pumps are switched on to pump the drilling mud down the drill string to the bit from surface, and back up the annulus carrying the cuttings. The pressure inside the tubular drill string is different from the pressure outside the tubular in the annulus—and is typically much higher. This pressure differential causes the body of the tubular to effectively act as a pressure vessel where it elastically deforms under the applied pressure load. This affects the measurements made by weight on bit sensors attached to the tubular. Specifically, the measurement accuracy is dependent on the pressure differential, which is directly correlated to the actual mud flow rates. In addition, when the mud is flowing, the temperature which each strain gauge experiences will vary, and consequently their absolute measurement of the weight and torque will also vary.
Various attempts have been made to correct for these pressure and temperature effects on the measurements, in the hope of enabling accurate weight on bit/torque measurements to be taken.
U.S. Pat. No. 4,608,861 discloses a device with an outer and inner sleeve, for isolating ambient pressure. It discusses the requirement for accurate temperature measurement to eliminate temperature related effects observed by strain gauges.
U.S. Patent Application 2010/0319992 discloses the concept of determining the correct weight on bit by the addition of strain gauges to a drill bit, and also the monitoring of pressure differentials across an effective area of the drill bit while drilling the well bore.
U.S. Pat. No. 6,547,016 discusses the problems associated with a drill string version of strain gauges, and tries to overcome the effects of bending on the measurements by deploying a Wheatstone bridge arrangement of strain gauges, which is a common method in strain gauge technology.
U.S. Pat. No. 6,957,575 discusses the effect of downhole pressure on the weight on bit measurement, and addresses the problem by determining an optimum position for the attachment of strain gauges, where there is null axial strain.
All of these existing documents discuss the problems associated with the deployment and use of sensors in a drilling environment. This presents certain unique challenges. In particular, the prevailing temperature and hydrostatic pressure changes as the drill bit is advanced; the drilling mud is pumped down the string from surface, and the pump pressure can be varied; dynamic errors occur during the drilling process, dependent on factors such as the relative hardness of the formations being drilled and passage of the drill bit through the formations and torque build-up/sudden release in the drill string. These and other issues impact on the ability to accurately measure strain and/or torque in a drill string, as will readily be understood from a review of the prior publications mentioned above.